REG - Pantheon Resources - Strategy Update

Pantheon ResourcesAnnouncement

21/11/2023 16:45

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RNS Number : 1862U  Pantheon Resources PLC  21 November 2023

 

 

 

 

 

21 November 2023

Pantheon Resources plc

Strategy Update - Pathway to Financial Self-Sufficiency

 

Pantheon Resources plc (AIM: PANR) ("Pantheon" or the "Company"), the oil and
gas company with a 100% working interest in the Kodiak and Ahpun projects,
collectively spanning 193,000 contiguous acres in close proximity to pipeline
and transportation infrastructure on Alaska's North Slope, is delighted to
take this opportunity to consolidate the narrative around progress to
achieving its objective of sustainable market recognition of $5-$10 per barrel
of 1P/1C recoverable marketable liquids by 2028.

 

In June 2023, Pantheon embarked on a renewed strategy, promising to keep
investors informed regularly, to share progress as it arises and to drive
progress to financial self-sufficiency as quickly as possible and at minimum
possible value dilution to existing shareholders.

 

Highlights:

 

·    Pantheon's strategy revolves around Final Investment Decision ("FID")
at Ahpun by the end of 2025, bringing it on stream in 2026, and completing the
appraisal of Kodiak ahead of its planned FID in 2028

·    Conservative estimate of the capital required for first production is
$120 million

·    Pantheon's strategy to reduce the equity capital required is based on
three main pillars:

o  Vendor financing

o  Offtaker financing

o  Reserves based lending

·    For conceptual development planning purposes, Pantheon has assumed a
typical well profile based on more conservative properties than encountered in
the long term test at Alkaid-2

·    A transition programme to achieve Sarbanes-Oxley compliance in time
for a potential US listing in 2025 is underway.

 

David Hobbs, Pantheon's Executive Chairman, commented: "The team has
undertaken a great deal of analysis and refined our planning case to ensure
that we organise funding on an appropriately conservative basis. We look
forward to putting the whole story together to help investors understand the
different milestones on the way to full field developments, with FID on the
whole of Ahpun planned for late 2025 and for Kodiak during 2028."

 

Field Definitions

Earlier this year, in an effort to simplify the understanding of Pantheon's
resources, a new naming convention was implemented, characterising all leases
into two fields; (i) Ahpun (comprised of the geologically youngest reservoirs
above the Hue Shale and mostly in the east of the lease holdings) and (ii)
Kodiak (comprised of the deeper reservoirs below the Hue Shale but above the
HRZ Shale, mostly to the west). Within Ahpun, there are reservoirs that have a
variety of depositional facies (descriptions of where and how a horizon was
deposited) which Pantheon has previously used to distinguish between the main
reservoir members. However, this risks giving the impression of greater
certainty about the distribution of pay zones within an overall trap (as is
the case with Ahpun) where multiple sand bodies have been deposited but share
the same basic trapping mechanism under the Decker D horizon.

 

In future, the Company will stop differentiating between different horizons in
its resource estimates and begin assigning such estimates at the field level.
For the time being, the Company's previously disclosed resource estimate for
Ahpun of 481 million barrels includes estimates for some members within what
has been called the Shelf Margin Deltaic ("SMD") and the upper part of the
Alkaid Zone of Interest ("Alkaid ZOI") and some, but not all, of the resources
from the Alkaid Deep, while excluding the Slope Fan System ("SFS") and some
zones within the SMD. As these additional reservoir intervals are appraised
and evaluated, their contribution will be included in Ahpun's resource
estimates.

 

Strategic Plan Highlights

The Company's refreshed strategy involves bringing Ahpun on stream in 2026
with FID planned by end of 2025, completing the appraisal of Kodiak (likely
requiring an additional 3 wells) ahead of its planned FID in 2028 and reaching
positive operating cashflows that cover capital investment needs during the
intervening period such that Kodiak's development would be fully funded from
Ahpun net revenues.

 

For the avoidance of doubt, the Company's estimate of the contingent resources
in the Ahpun Field remains at some 481 million barrels of marketable liquids
and the development of the field is planned in two stages. The first will
access some 200 - 300 million barrels expected to be recoverable from pads
located within the disturbed corridor alongside the Dalton Highway and Trans
Alaska Pipeline System (TAPS). The second stage is expected to access the
remainder from pads located further to the South and West (i.e. outside the
disturbed corridor).

 

Netherland, Sewell & Associates, Inc. ("NSAI") is developing a resource
estimate for Ahpun, including both the deeper horizons tested in the Alkaid-1
and Alkaid-2 wells and the remaining, geologically shallower shelf break
horizons encountered in Pipeline State, Talitha-A and flow tested in the
Alkaid-2 re-entry. This report will be issued around the middle of 2024.

 

NSAI has already delivered an independent 2C contingent resource estimate for
the Kodiak Field with oil, condensates and natural gas liquids ("NGL")
totalling nearly 1 billion barrels. Pantheon has previously presented analysis
based on reducing maximum depths of burial ("Dmax") leading to expected
improvements in reservoir properties in Kodiak moving further to the Northwest
from Theta West-1. The Company is continuing its analysis of the updip
resources to support the future appraisal programme prior to Kodiak's FID in
2028. Pantheon believes these additional resources will support the Company's
previously disclosed management estimate of total expected ultimate recovery
("EUR") for Kodiak of 1.78 billion barrels.

 

Development of the discovered resources will be conducted in a similar manner
to the Permian Basin, with year-round operations from well pads connected by
gravel roads. This is normal practice on the North Slope. The precise
transition from Ahpun to Kodiak development will be an economic decision
following FID for Kodiak. From the portfolio of available drilling locations,
Pantheon will allocate capital to the highest value well or cluster of wells,
optimising for the value delivered to the aggregate portfolio.

 

The eventual optimum development plan may result in incremental pads moving
from East to West or it may involve more significant step outs to the
Northwest (expected to contain the highest quality resources). The planning
assumptions for the base case development are explained below - assuming all
drilling locations exhibit only the reservoir quality encountered in the test
of the "Alkaid ZOI" horizon in the Alkaid-2 well, as reported early in 2023.
In reality, the Company expects the resources in the Northwest of the 193,000
acre lease position to consist of more than 1,000 ft of pay with up to 50% of
the reservoir exceeding the commonly recognised threshold to be classified as
conventional.

 

Capital Investment and Funding

The entire development of Ahpun and Kodiak, using the conservative planning
basis noted above, is likely to require more than 2,000 wells, including gas
and water injection wells, over the long life of the field. This will cost
approximately $25 billion in today's money. This seems like a very large sum,
but in common with many such projects, most of the development costs will be
incurred after the fields have begun production and through the reinvestment
of production revenues and debt. The more relevant figures are:

·    the capital that needs to be invested prior to production start-up;

·    the maximum negative cumulative cashflow prior to being able to
access secured debt (expected to be reserves based lending); and

·    the maximum negative cumulative cashflow beyond which future capital
and operating costs are self-funding - the Company refers to this as financial
self-sufficiency.

 

These sums have previously been estimated conservatively at $120 million prior
to production start and $300 million maximum negative cumulative cashflow on
the Ahpun development (plus potentially $50 million of Kodiak appraisal
costs). A more detailed description of how these figures can be calculated is
provided below.

 

The net negative cashflow up to the point at which debt funding could be drawn
down depends on a number of factors, including how the Company's oil is
marketed (in whole cargoes or lifted in combination with other producers) and
the precise timing of when additional groups of wells are brought on stream.
For simplicity, Pantheon's development plan modelling assumes no reserve based
lending is available until the first year's nine production wells are all on
stream.

 

The strategy for minimising dilution of existing shareholder value is built on
three main pillars:

 

I.     Vendor financing - negotiating a delay in the timing of payments
for services during the first twelve months of activity, at a commercial
interest rate, in return for a long term, directly negotiated contract for the
proposed 1,000+ wells based on market rates and margins with incentives for
beating cost targets to create a win-win relationship. The share of costs that
could be subject to such arrangements is expected to exceed $100 million
during the first 12 months of development, of which the majority will be
incurred after first production.

II.    Offtake financing - negotiating bankable contracts from buyers of
marketable liquids and, if appropriate, natural gas. Liquids have the
potential to be financed through volumetric production payments, among other
options. The State of Alaska has made significant progress in moving a gas
pipeline project forward for delivery of natural gas to South Central Alaska
with subsequent exports of LNG. Pantheon believes it would be well positioned
to secure some sales of associated gas that would otherwise be reinjected into
its reservoirs.

III.   Reserves based lending - once production is established from enough
wells to meet lender risk management criteria on diversification, the Company
will seek to draw down on lending facilities, which would have been arranged
prior to production start-up, supported by borrowing base calculations from
mutually accepted third party engineers. The modelled production profile for a
typical production well ("type curve") is outlined below in the Company's
"Planning Basis". For illustrative purposes, based on previous calculations,
each such modelled incremental well brought on stream has the potential to
deliver an estimated $20-$25 million of fresh liquidity, allowing a rapid
drawdown on such a facility up to an initial target of $250 million;
sufficient to achieve the total of $350 million prior to Kodiak FID and to
achieve financial self-sufficiency when combined with other funding channels.

 

In aggregate, other than the expected satisfaction of the Convertible Bond,
due for repayment by mid December 2026, Pantheon intends to reduce the amount
of additional equity capital required substantially. However, the timing and
quanta of each of these funding options is uncertain and there can be no
guarantees of success with all or any of these options. The Company's
confidence in achieving a successful outcome is, however, built on its
conservative planning basis that provides substantial upside to potential
funders above the base case.

 

In parallel with these funding avenues, the Company is exploring options with
one or more potential farm-in partner(s) who, if discussions were to progress,
might contribute to the capital costs of bringing the assets on stream in
return for a working interest in the leases or economically equivalent
structure. Any transaction is only likely if it represents less dilution of
value to shareholders than alternative avenues. Pantheon management believes
there is appreciable strategic value in its operatorship and 100% working
interest in the resources.

 

Base Case for Development Planning

For conceptual development planning purposes, Pantheon has developed an Ahpun
field "type curve" - a term meaning a representative, typical well production
profile. The Company applied the most conservative of these estimates for
rates and volumes to generate the type curve (previously presented at the June
28(th), 2023 webinar).:

·    IP30 (average production rate over the first 30 days) of 1,500
barrels per day ("bpd") of marketable liquids

·    1 million barrels of marketable liquids EUR

For conservatism, this was derived from the performance seen in the 90 day
flow test of the deepest, lowest quality reservoir horizon in the Ahpun field:

 

 

 Year             1    2    3    4    5    6    7    8    9    10
 barrels per day  953  466  298  225  183  154  134  119  107  96

 

The analysis results in a 60% first year decline rate (from 1,500 bpd in the
first month of stabilised production to 600 bpd in the 13(th) month) before
levelling off to an ultimate 10% decline rate. This type curve was created by
estimating the performance from doubling the lateral length (from 5,000 ft to
10,000 ft) and doubling the frac efficiency to 40% (i.e. less than half the
more typical 80% experienced in major unconventional plays in the US lower 48
and less than the c. 50% achieved in the subsequent frac of the shallower
horizon in the Alkaid-2 wellbore). In other words, the conceptual development
plan is based on there being no improvement in well performance beyond that
demonstrated to be feasible at the Alkaid-2 location.

 

The successful re-entry of the Alkaid-2 well to test the shallower reservoir
interval demonstrated the benefit of a revised frac design (fewer
perforations, finer proppant, higher pump rates and additional chemicals to
prevent emulsion blockage in the reservoir), justifying the Company's
confidence in the opportunity to more than double the frac efficiency. The
reservoir quality in the geologically shallower horizons of Ahpun (which are
thicker and better developed to the south and west of the Alkaid-2 location,
is an order of magnitude higher than was encountered in the 5,000 ft lateral.
Furthermore, the initial estimates of the gas-oil ratio are lower than
experienced in the original 90 day test, implying upside from the perspective
of fluid composition. None of these incremental benefits arising from the
subsequent field test are currently incorporated into the type curve.

 

This conservative development planning basis implies that some 650 wells would
be required to produce the entire contingent recoverable resource based on 60
acres of drainage area per well (assuming 10,000 ft laterals and 300 ft
horizontal frac propagation) including the gas/water injection wells.

 

To give an idea of the resilience of the economics of these wells at $80 per
barrel ("bbl") ANS (the quoted price of Alaskan North Slope Crude, delivered
to a US West Coast Refinery), the payback on this profile is estimated to be
less than 12 months. Even at $70/bbl, this payback period is calculated at
less than a year.

 

In planning the Kodiak Field base case, the Company has used the same type
curve and cost. This is despite a reservoir with some 1,000 ft of productive
pay, the shallower depth of wells and the expectation of superior quality
conventional reservoir representing 50% of the net pay. This means that a
large number of wells may not require 10,000 ft laterals with 60 frac stages,
but instead can be completed at materially lower cost as conventional
horizontal or highly inclined producers with a single longitudinal frac
(analogous to wells in the Kuparuk Field and the Santos operated Pikka
development).

 

Future appraisal wells will determine the optimum development of Kodiak but,
in the interests of conservatism, the Company is assuming that there will be
no improvements in reservoir or fluid properties beyond those already
encountered in the Alkaid-2 well (i.e. ignoring the increase in average
porosity confirmed in Theta West-1 and the anticipated continuation of the
improvements to the Northwest).

 

Detailed Cost Breakdown for Capital Cost to First Production

In previous webinars and press releases, the Company has estimated the costs
of achieving first production at $120 million, consisting of:

 

·    $20 million for the tie-in to the TAPS main oil line (with a capacity
of 200,000 bpd)

·    $20 million to upgrade the existing production facilities, including
a chiller for NGL recovery

·    $20 million each for three production wells for a total of $60
million for drilling and completion

·    $20 million for overheads between now and production start up

 

Again, for the avoidance of doubt, the Ahpun FID is for the full field
development. The $120 million outlined above is just the cost of the three
wells expected to be drilled by the time production starts up as well as the
other items listed above. It is assumed that the cost of converting the
Alkaid-2 well to be an injector is included in this total (included in the
cost of facilities upgrade).

 

Detailed Calculation of Maximum Cumulative Negative Cashflow

The Company has estimated the maximum cumulative negative cashflow at $300
million (before any financing arrangements are included and excluding
approximately $50 million for further appraisal wells at Kodiak). This is
based on drilling 10 wells in the first year (of which eight would be
production wells) and a further 16 wells in the second year (of which 12 would
be production wells). Modelling the first and second year averages from the
type curve, and adding the wells evenly throughout the year after production
start-up, results in average production through the seven months to the end of
the first year of development of approximately 5,300 bpd (4,350 bpd net of
royalties). Pantheon's latest estimates of operating costs are $12,500 per
well per month plus $3/bbl of gross production. Thus, the position at the end
of the first year of development if ANS averaged $80/bbl is modelled to be:

 

Year 1 Costs ($287 million)*

$120 million to first production

$105 million for seven further wells at $15 million each

$30 million of Capex for Phecda pad & production facility to allow two
rigs operating

$5 million of Opex (on 5,300 bpd average)

$8 million of Tariffs & Tankers

$5 million of G&A Overhead

$14 million of Royalties

 

Revenues before tax ($81 million)*

$81 million (on 5,300 bpd average x $72/bbl after quality adjustment)

 

Cumulative negative net cashflow by end of first year = $206 million*

 

*modelled numbers may not add exactly because of rounding

 

In the second year, again with ANS Crude selling at $80 per barrel, this nets
back to around $72/bbl at the entry to the pipeline after adjusting for
quality. Production during the second year is modelled to average 12,700 bpd
(10,400 bpd net of royalties), which would yield approximately $270 million of
revenues net of royalties. Tariffs of $32 million, capital costs of around
$240 million and operating costs including G&A of around $22 million
during the year would result in an approximate breakeven for the year but the
peak net cumulative cash outflow would be around $230 million as a result of
production building up through the year. The incremental expected cumulative
outflow to get to the $300 million (maximum negative cumulative cashflow on
the Ahpun development) figure assumes worst cases for marketing of ANS crude
and TAPS transportation services.

 

The precise moment that financial self-sufficiency is achieved is sensitive to
the exact timing of wells coming on stream and the price realisation.
Pantheon's strategy will be to maximise liquidity to weather the inevitable
expected "unexpecteds" (events that cannot be defined without the benefit of
hindsight but are anticipated to occur) without diluting more than necessary
to preserve value for existing shareholders.

 

Company Best Estimate for Development Planning (based on SLB Analysis)

Development studies by SLB indicate an alternative type curve for the Alkaid
horizon substantially in excess of Pantheon's base planning case estimates.
Utilising this analysis, Pantheon has created a best estimate using an IP30 of
2,700 bpd and EURs of 1.65 million barrels. Improvements seen in the shelf
break horizons in Ahpun and the updip portions of Kodiak would see rates and
volumes comfortably exceeding these.

 

Utilising these estimates, and modelling monthly production rates for each
well as it is added, the rate of production build up is more rapid with a peak
cumulative net cash outflow of $160 million and financial self-sufficiency
being achieved before the end of 2026. However, it seems more prudent to plan
on the basis of the more conservative type curve.

 

-ENDS-

 

Further information, please contact:

 

 Pantheon Resources plc                                       +44 20 7484 5361
 David Hobbs, Executive Chairman

 Jay Cheatham, CEO
 Justin Hondris, Director, Finance and Corporate Development

 Canaccord Genuity plc (Nominated Adviser and broker)
 Henry Fitzgerald-O'Connor                                    +44 20 7523 8000

 James Asensio

 Gordon Hamilton

 BlytheRay
 Tim Blythe                                                   +44 20 7138 3204

 Megan Ray

 Matthew Bowld

 

 

In accordance with the AIM Rules - Note for Mining and Oil & Gas Companies
- June 2009, the information contained in this announcement has been reviewed
and signed off by David Hobbs, a qualified Petroleum Engineer, who has nearly
40 years' relevant experience within the sector.

 

 

Notes to Editors

 

Pantheon Resources plc is an AIM listed Oil & Gas company focused on
developing the Ahpun and Kodiak fields located on state land on the Alaska
North Slope ("ANS"), onshore USA where it has a 100% working interest in
193,000 acres. Certified contingent resources attributable to these projects
exceeds 1 billion barrels of marketable liquids, located adjacent to Alaska's
Trans Alaska Pipeline System ("TAPS").

 

Pantheon's stated objective is to demonstrate sustainable market recognition
of a value of $5-$10/bbl of recoverable resources by end 2028. This will
require targeting Final Investment Decision ("FID") on the Ahpun field by the
end of 2025, building production to 20,000 barrels per day of marketable
liquids into the TAPS main oil line, and applying the resultant cashflows to
support the FID on the Kodiak field by the end of 2028.

 

A major differentiator to other ANS projects is the close proximity to
existing roads and pipelines which offers a significant competitive advantage
to Pantheon, allowing for materially lower infrastructure costs and the
ability to support the development with a significantly lower pre-cashflow
funding requirement than is typical in Alaska.

 

The Company's project portfolio has been endorsed by world renowned experts.
Netherland, Sewell & Associates ("NSAI") estimate a 2C contingent
recoverable resource in the Kodiak project that total 962.5 million barrels of
marketable liquids and 4,465 billion cubic feet of natural gas. NSAI is
currently working on estimates for the Ahpun Field.

 

 

 

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